Inflatable packers may be attached to coiled tubing and deployed into a wellbore to perform various hydrocarbon wellbore operations. For example, such operations include, but are not limited to, setting the inflatable packer (i.e. expanding a packer to seal off a section of the wellbore) and stimulating the wellbore formation above or below the packer by pumping a treatment fluid, such as an acid into the formation, and setting the inflatable packer and pumping a water shut off fluid above or below the packer to stop water flow into the wellbore from a particular zone of the formation.
In each of these scenarios, the packer is typically unset and retrieved from the wellbore at the end of the wellbore operation. In another scenario, the packer is set and then the coiled tubing is detached from it. Cement can then be poured on top of the packer creating a plug in the wellbore. The packer, in this case, is permanently left in the wellbore.
For a packer, such as an inflatable packer, to function properly, it is desirable that the differential pressure between an inside and an outside of the packer stays below a certain differential threshold. This threshold is different for different packer designs. As the expansion ratio of the packer increases (in other words as the packer is inflated in larger wellbores, or as the amount of radial expansion needed for the packer to engage a wellbore wall goes up) the differential pressure that the packer can withstand decreases. This is a limiting factor in many cases for inflatable packer operations. Often times during the design of a wellbore operation, the operator needs to consider the setting diameter of the packer and what the differential pressure is going to be at different stages of the operation.
The pressure inside the coiled tubing is usually applied to the packer during an inflation or expansion of the packer. This pressure is created by the hydrostatic pressure of the column of fluid in the coiled tubing and a pump connected to the coiled tubing at a surface of the wellbore.
The most common ways of creating inflation pressure in an inflatable packer to radially expand and “set” the packer in a wellbore are by orifice inflation and by bullhead inflation. In orifice inflation, a coiled tubing fluid is pumped through a single or a set of orifices. A portion of the fluid goes into the packer and is used to inflate the packer. This is a flow rate dependent inflation process. Flow rate is increased in a step by step fashion and at every step more fluid goes into the packer. In bullhead inflation, a coiled tubing fluid is applied directly into the packer. This is a pressure driven inflation technique rather than a flow rate dependent one. Therefore, it is a harder-to-control type of inflation process. Since the packers only need a very small volume of fluid (typically around 3-15 gallons) the inflation process is performed by discrete pumping instead of the constant pumping that is needed for orifice inflation.
Wellbores having low bottom hole pressure pose a particularly challenging problem when it comes to running inflatable packers. In these wellbores, the hydrostatic pressure of the fluid inside the coiled tubing is greater than the bottom hole pressure in the wellbore, which may cause an inflatable packer to inadvertently start inflating as the coiled tubing is lowered into the wellbore. To prevent an inflatable packer from inadvertently inflating, a common practice is to limit an amount of fluid in the coiled tubing as it is lowered into the wellbore. This is sometimes referred to as dry running, and may involve filling the coiled tubing to about 20% of its capacity. However, although this technique helps with the inadvertently inflating problem, it is not ideal.
It is desirable, therefore, to provide an improved process and/or apparatus for setting an inflatable packer in a subhydrostatic wellbore.